Wind Tax Equity Update

Publication November 12, 2015

Two chief financial officers of major US wind companies and three leading tax equity investors talked in mid-October about how much tax equity can be raised on wind farms, current yields, the effect that low capacity factors and falling electricity prices are having on deals, the extent to which the tax equity market will finance projects that relied on modest physical work at the project site or a transformer factory to get under construction in late 2014, whether tax equity can be raised on 2017 projects, developer fees and other issues. The conversation took place at the American Wind Energy Association’s annual finance conference in New York.

The panelists are Bernardo Goarmon, executive vice president and chief financial officer of EDP Renewables North America, Tom Festle, chief financial officer of E.On Climate & Renewables North America, Jack Cargas, a managing director at Bank of America Merrill Lynch, Yale Henderson, a managing director at JPMorgan Capital Corporation, and Kenji Ogawa, a managing director at MUFG Union Bank. The moderator is Keith Martin with Chadbourne in Washington.

 

MR. MARTIN: Bernardo Goarmon, CFOs can draw on various kinds of capital. There are loan guarantees, export credits and other forms of government-assisted debt, straight debt, tax equity, back-levered or subordinated debt and true equity. What share of the capital for the typical wind farm today comes from tax equity?

MR. GOARMON: For a project on which production tax credits will be claimed, probably between 55% on the low end to 75% on the high end for a project with high wind performance and, therefore, more tax credits.

MR. MARTIN: Tom Festle, same number?

MR. FESTLE: Yes, same range. We try to invest in high wind areas with competitive construction costs.

MR. MARTIN: Yale Henderson, the figures we have heard so far are the amount of tax equity that can be raised in a partnership flip transaction. What determines whether the transaction will raise 55% or 75% of the capital cost?

MR. HENDERSON: A number of factors. They are the wind regime, how many production tax credits are being generated, the asset cost and the amount of depreciation. Ultimately, the CFO is trying to optimize the structure by retaining as much cash as possible. Monetizing cash flow through the tax equity deal is not a goal of the CFO, and we are happy to accommodate him or her because it makes for a safer transaction from our perspective.

MR. MARTIN: The less cash the tax equity investor gets, the closer you are to the bottom end of the range. Bernardo said 55% at the low end.

MR. HENDERSON: For a PTC deal you never get below 50% because, if you do, then you will not be able to monetize the depreciation effectively. The low end of the range is probably 50% for a PTC deal and in the 40% range for an ITC deal.

MR. MARTIN: Kenji Ogawa, Tom Emmons from Rabobank said on the panel immediately before this one that he has not seen a leveraged partnership flip deal for a long time. Is that structure now extinct and, if so, why?

MR. OGAWA: I would not say that it is extinct, but it is selectively used. You really need scale to make the numbers work. In addition, there are probably only three or four tax equity investors who will consider doing a leveraged tax equity transaction. You need a large project with low risk and low variability in the wind regime.

MR. MARTIN: Jack Cargas, agree?

MR. CARGAS: I would call it extinct.

MR. MARTIN: Yale Henderson?

MR. HENDERSON: It’s dead.

MR. MARTIN: Bernardo Goarmon, is anyone claiming an investment tax credit instead of production tax credits on new wind farms?

MR. GOARMON: Frankly, we do not see the economics working for investment credits. PTCs are a superior way of financing.

MR. MARTIN: Tom Festle, do you agree?

MR. FESTLE: We always look, and it never works. Our projects are too productive.

MR. MARTIN: Kenji Ogawa, have you seen any ITC deals recently in the wind market?

MR. OGAWA: I am aware of only one wind deal this year that was done on ITC basis.

MR. MARTIN: Why was it done that way?

MR. OGAWA: Cost.

MR. MARTIN: It was a very expensive project?

MR. HENDERSON: It was in a relatively weak wind regime in the northeast. There are a few that make sense on an ITC basis, but they are needles in a haystack.

MR. MARTIN: Tom Festle, in view of those answers, do we need to preserve the option for companies to claim the ITC when lobbying Congress?

MR. FESTLE: It is not a high priority for us.

MR. GOARMON: If we start adding large batteries to projects, then maybe the ITC will make more sense.

MR. MARTIN: I was going to go there next. Let’s talk about batteries. Is EDP adding batteries to its wind farms and how will that change the equation? It makes the whole project more expensive without generating more electricity.

MR. GOARMON: We are not adding storage currently, but it is something we may do in the future. Storage tips the scale back toward ITCs if batteries are an integral part of the facility. The more expensive the project, the more advantageous it is to claim a tax benefit tied to cost. The greater the output, the better it is to claim a tax benefit tied to output.

MR. MARTIN: Tom Festle, is E.On adding batteries currently?

MR. FESTLE: It is something we are considering, but we have not done it yet. We are likely to do it at our solar projects before adding batteries to wind farms.

MR. OGAWA: Batteries are a reason to preserve the ITC. The ITC is not available for batteries on a standalone basis, but if you have a battery as part of a wind or solar project on which an ITC is claimed, then you may be able to claim an ITC on the entire project cost, including the battery. If you were to add a battery to a PTC project, then the battery would simply be a drag on cost and not qualify for an additional tax benefit.

MR. HENDERSON: I also assume that the only way offshore wind farms will be built is with investment tax credits.

Yields

MR. MARTIN: Kenji Ogawa, my impression is that tax equity yields have been trending down in the last six months. Do you agree?

MR. OGAWA: It depends on how you define slipping. I would say they have been relatively stable within a range. [Laughter]

MR. MARTIN: Yale Henderson, can you do better than that?

MR. HENDERSON: That was right and sweet. [Laughter]

MR. MARTIN: Jack Cargas, I am not going to ask you, unless . . . .

MR. CARGAS: Yes, they have been slipping.

MR. MARTIN: Bernardo Goarmon, where do you think tax equity yields are currently in flip deals?

MR. GOARMON: Still far too high! Let me just share the way I like to convey it to people overseas. Tax equity is a sophisticated product. Ironically, the pricing mechanism is as simple as it can get. It is supply and demand. The tax equity investors seem to be disciples of Adam Smith.

MR. MARTIN: Tom Festle, where do you think yields are currently?

MR. FESTLE: I heard somebody say on the last panel that they are between 7% and 8%. That range sounds reasonable. We are going out to market shortly, and we hope to see yields going down. They are still high compared to when we did our first deal in 2007.

MR. CARGAS: It is not clear that people measure the cost of tax equity appropriately. People talk about whatever the yield is. Tom Festle says 7% to 8%. We do not quote rates publicly, but call it somewhere in that range. That is the return to the tax equity, including tax benefits. These transactions are done by sponsors because they cannot use those tax benefits, so 7% to 8% is not a genuine cost. Part of the return to the tax equity comes from outside the transaction. It comes from the US government. I think the appropriate comparison ought to be to pre-tax internal rates of return, which is a better measure of the real cost to the sponsor.

MR. MARTIN: I am glad you brought that up. Now, let me press you on that. What do you need as a pre-tax yield?

MR. CARGAS: Sorry? [Laughter]

MR. MARTIN: Yale Henderson, what pre-tax yield does JPMorgan require: 2%? We heard from Invenergy on the previous panel that tax equity investors are requiring pre-tax yields of 1% to 2%.

MR. HENDERSON: Every tax attorney and every shop has his or its own benchmark, but 2% plus or minus is the right number. Of course, that is the pre-tax cash plus PTCs. If you look solely at the cash we are taking out of the project, we are making a negative internal rate of return. A lot of that flip IRR of 7% or 8% is tax savings from depreciation, which people have to understand produces no book earnings for us. The point is there are a lot of things that go into pricing when we look at a transaction.

MR. GOARMON: I agree with the up to 2% range for pre-tax yields. They are a proxy for long-term inflation. I disagree with Yale that there is a lot that goes into pricing. Pricing seems to be simple.

MR. MARTIN: Kenji Ogawa, what pre-tax yield does Union Bank require?

MR. OGAWA: The numbers that Yale quoted on the plus side are probably right.

MR. MARTIN: On the plus side. Tom Festle, are you seeing tax equity ask for a higher 20-year yield. Maybe 50 basis points higher?

MR. FESTLE: The last time we were in the market was at the end of last year. We will be back in soon. With that in mind, we do see some markup for a 20-year yield.

MR. GOARMON: We look at the period after the flip where we keep most of the value. Yes, there is a premium during this period for the tax equity investor, but it is a small premium. We like to measure it over 25 years.

MR. MARTIN: The yield premium is not 50 basis points?

MR. GOARMON: No, it is not; 25 basis points is more common from where we stand.

MR. OGAWA: One of the things you really need to look at is the profile of the project. The stronger the profile, the higher your back-end 5% is going to get you.

MR. MARTIN: The stronger the project, the higher the premium you will receive?

MR. HENDERSON We are not sitting there saying we need another 50 basis points above the flip IRR by year 20 or 25. The real driver is the pre-tax yield we are trying to hit. That will also drive what we end up with as an after-tax IRR. The additional yield at year 20 or 25 could be 25 to 50 basis points or even higher if you have a project with a merchant tail.

MR. CARGAS: I agree with that. We track those numbers, but most tax equity investors do not insert a minimum requirement or a minimum spread between the flip yield and the full-term yield.

MR. MARTIN: Kenji Ogawa, how common are structuring fees?

MR. OGAWA: They are a market-driven mechanism. The more complicated the structure, the more likely you are to see a structuring or commitment fee.

MR. MARTIN: Market-driven means that if you can get it, you ask for it? [Laughter]

MR. HENDERSON: I don’t think they are structuring fees. I think they are commitment fees, and I think the market today is looking for longer-term commitments. The amount of regulatory capital and the cost of capital for those commitments have increased, so the market is taking that into account, particularly for parties who need commitments of six, nine or even 12 months before a project goes into commercial operation.

Weather and Falling Prices

MR. MARTIN: Bernardo Goarmon, wind output has been below expectation this year in places like Texas, California and the Pacific Northwest. In Texas, an average capacity factor in the first half of 2015 was just below 30%, compared to 38% the year before. How has that affected your existing tax equity deals for projects in these locations?

MR. GOARMON: We have not seen such a significant gap in our portfolio. It is about half the gap you just described both in Texas and California. Other markets, like New York for instance, are slightly better than the long-term expectations. So far we have not seen any impact on our ability to arrange new tax equity transactions. We think that there are always good and bad years, and they average out. For example, 2012 was good, 2013 was good, and 2014 was a record first quarter. This is just the nature of the business.

MR. OGAWA: I think that most investors understand that the wind varies from one year to the next.

MR. HENDERSON: The partnership flip structure works well for projects with variable output because low performance one year does not lead to cash being trapped or payment defaults. We are not lenders. We are a form of preferred equity. We ride along with the ups and downs of the project.

MR. MARTIN: Jack Cargas, you are based in California. You see low capacity rates. Do they change how you will do deals going forward?

MR. CARGAS: They might. We are thinking hard about this. We hear our sponsors say that this is an anomaly that will be offset by better performance in other years, but we are tracking it closely. It has affected our portfolio. Certain transactions within our portfolio have been affected significantly. You asked how it will affect the deals we do in the future. For past transactions, it could push flip dates out. For new transactions, we are doing more sensitivity analyses. There is a decent chance that we will see larger haircuts in base case models.

MR. MARTIN: Are you pricing off P99 and applying a haircut to that?

MR. CARGAS: This is not something we have done yet. We are thinking about it. Right now, we are pricing off the expected case. We are starting to look at a larger range of possible outcomes. Exactly what we will do with that data is not yet clear.

MR. MARTIN: Power prices are falling. Thirteen power purchase agreements were signed last year for 1,768 megawatts of wind farms. The average price for the electricity was $23.50 a megawatt hour. The average cost to build wind farm was $1.71 million per installed megawatt. Do falling wholesale power prices affect how you will do deals going forward?

MR. FESTLE: The good news is that the capital cost to build a wind farm is falling at the same time. It just reinforces the need to optimize every transaction for wind and cost, both of which can vary significantly from one site to the next.

Corporate PPAs

MR. MARTIN: Yale Henderson, one of the big stories this year has been the number of corporate PPAs signed. Fifteen hundred megawatts had been signed by mid-year. We are expecting about 3,000 megawatts to have been signed by year end. Are you indifferent to whether the PPA is with a corporate offtaker or a utility? Does it come down simply to the creditworthiness of the offtaker when deciding whether you will do a tax equity deal?

MR. HENDERSON: Essentially, yes. Obviously, everybody likes a nice regulated utility backstopping the power pricing; it gives everybody comfort. But I think we are well-positioned, as a large bank, to evaluate the credit of corporate offtakers. We probably have a relationship with them already, so we are willing to roll up our sleeves and figure out what the credit is.

The bigger challenge is that a lot of those entities are not willing to use their balance sheets. They put these PPAs into standalone special-purpose subsidiaries and are offering little credit support, even when the parent is creditworthy. It is tougher to get comfortable with that. There is also a basis risk issue in corporate PPAs that is not present with utility PPAs because the electricity sold under corporate PPAs is often priced at a hub rather than the bus bar. We are able to get comfortable with the basis risk, but it is just another complication.

MR. GOARMON: We saw this train coming and prepared ourselves for it. We have a disciplined approach to negotiating PPAs. Our finance team is closely involved and on the lookout, among other things, for the quality of credit package and embedded derivatives for book purposes.

MR. MARTIN: Tax equity investors, would you do a deal with a virtual PPA? A lot of the corporate PPAs are essentially hedges or contracts for differences rather than physical trades.

MR. OGAWA: Yes. As Yale said, the biggest risk with corporate PPAs is the long-term creditworthiness of the offtaker, and then, secondarily, the basis risk on the settlement point of the contract.

MR. MARTIN: With a virtual PPA, there may also be risk that the electricity will find an outlet. The virtual PPA merely places a floor under the electricity price.

Construction-Start Issues

MR. MARTIN: Jack Cargas, are tax equity investors financing projects that started construction in 2014 under the physical work test?

MR. CARGAS: Yes.

MR. MARTIN: There are various ways a developer could have started physical work. Do you have a preference for roads, turbine excavations, transformers, substation foundations? How much work do you need to see?

MR. CARGAS: Clearly the more work, the better, but it is also clear that when the IRS provided additional guidance on this topic, it set a very low bar. A year ago, we were saying that a guy on site turning dirt with a shovel is not enough. We still say that, but three guys and a backhoe might be enough if they did the right work.

MR. MARTIN: Yale Henderson, how much physical work do you need to see, and do you have a preference for roads, transformers, turbine excavations, substation foundations? Are they all the same in your mind?

MR. HENDERSON: They are not all the same. We do not have a bright-line test. We evaluate each deal individually. We look hard at what work was done. Three guys and a backhoe? I am not sure we are there.

MR. MARTIN: A lot of developers will want to know this year, if they are given just two or three weeks to act, whether having a manufacturer do a small amount of work on a step-up transformer is enough. What do you think?

MR. HENDERSON: Spend real money, and you will be better off.

MR. MARTIN: Kenji Ogawa, is it enough to have started work on a transformer?

MR. OGAWA: I am with Yale on this one, too. There is no bright line. Depending on the size of the project, a transformer might be okay. I would defer to you and your esteemed colleagues on the tax side.

MR. MARTIN: Fair enough. Are there any issues with the physical work test that you think the IRS did not settle and needs urgently to address?

MR. OGAWA: If the IRS would make it a real bright-line test and not have it turn on facts and circumstances, that would be ideal.

MR. MARTIN: The bright line is called the 5% test.

The larger wind developers have bought turbine components in order to qualify their projects under the 5% test. Some of these projects will slip into 2017. Are tax equity investors willing to finance such 2017 projects? The developers must prove continuous efforts on the projects after 2014 to qualify for tax credits.

MR. CARGAS: We have not definitively answered this question frankly due to lack of time to analyze it. It is entirely possible we will get there, but we probably will not make this determination until sometime in 2016.

MR. MARTIN: Yale Henderson, same answer?

MR. HENDERSON: Pretty much. We have a lot of 2016 business to do first.

MR. MARTIN: Kenji Ogawa?

MR. OGAWA: Likewise.

MR. MARTIN: What happens if Congress does not extend the PTC?

MR. CARGAS: I have a view on this. There is a long history of structured asset finance in the United States that goes back at least 50 years. It will not be as dynamic a market, but to the extent there are depreciation-only transactions to be done, there will be sponsors who will take advantage of them.

MR. MARTIN: Yale Henderson, I assume the tax equity team at JPMorgan will need to find something to do. You will figure out how to continue doing tax equity deals, even with fewer tax benefits.

MR. HENDERSON: I started at First Chicago Leasing Corporation. The technology is there. The world has changed a lot since we did depreciation-only deals, both in terms of accounting and the willingness of banks to take 15- or 20-year risks, but, ultimately, like Jack said, we have figured out how to do such transactions in the past and we will figure this out again, if faced with the issue.

MR. MARTIN: Bernardo Goarmon, how common are developer fees in wind deals and at what level?

MR. GOARMON: Five percent is our typical. We see them more frequently in solar than in wind.

MR. MARTIN: Tom Festle?

MR. FESTLE: In some projects, we can add a lot of value as the developer and, in other ones, we add just a little value, so the fee varies.

MR. MARTIN: What is the range?

MR. FESTLE: It is hard to give a range.

MR. MARTIN: Some older flip deals are now getting to the point where they are about to flip or they have flipped. Lawyers and business people try to anticipate all the issues that might come up when drafting deal documents. Are there issues that have come up in the flip year that were not fully addressed in the standard partnership flip documents the market is using?

MR. FESTLE: We have not reached 10 years in any of our deals.

MR. GOARMON: We have had only one deal that flipped, so it is too early to speak.

MR. HENDERSON: We did our first deals in 2003 and have had some transactions reach the flip date. We have had a good experience with the deals that have flipped to date.

Tax Risks

MR. MARTIN: Have you seen tax indemnity payments having to be paid in any of your deals, and if so, about what issue?

MR. GOARMON: No.

MR. HENDERSON: No.

MR. CARGAS: Not in wind.

MR. HENDERSON: Are you asking also about the Treasury cash grant program and indemnities paid on account of grant shortfalls?

MR. MARTIN: Yes, I am. So there have been indemnities in connection with shortfalls in Treasury cash grants. Kenji Ogawa?

MR. OGAWA: Same answer on the cash grant program for shortages.

MR. GOARMON: My answer is still no.

MR. MARTIN: Tax risk is allocated in flip deals through representations and a series of fixed tax assumptions. Have you seen any shift in the last year about how tax risk is shared?

MR. GOARMON: Attempt, yes; success, not yet.

MR. CARGAS: We have seen a shift. The depreciation methods and periods used to be a fixed tax assumption. They are no longer one in the current market. That risk has shifted from investor to sponsor.

MR. MARTIN: Almost all flip deals have absorption issues, meaning the tax equity investor has too little capital account to absorb the full tax benefits he is allocated. Yale Henderson said earlier that a flip deal must raise at least 50% of the capital cost for the tax equity to have a shot of absorbing a reasonable amount of the depreciation on a project. Is the absorption problem getting addressed still by having the tax equity investor agree to a deficit restoration obligation, and what is a typical percentage DRO in the current market? It seemed to be in the low 20% range a few years ago and to have fallen to the low single digits lately. These are percentages of the tax equity investment.

MR. CARGAS: I think the range is all the way from the low single digits to the high 20s, maybe even crossing 30%. It depends on the transaction. It depends on the sponsor. Even more important than the day one cap on the DRO is the capital account deficit profile over time, and how quickly the deficit is expected to be eliminated over time. Ideally, we would like to see the deficit eliminated before we flip.

MR. MARTIN: Is the principal factor how quickly the base case model shows the deficit reversing?

MR. OGAWA: It is an important factor given how PPAs are being structured today. It is harder to reverse a DRO if the project has a PPA with level pricing that does not escalate over time.

MR. MARTIN: Jack Cargas, some tax equity investors are offering a time-based flip where the tax equity investor gets essentially 2% of its investment in cash each year as a preferred distribution and not much other cash. Are you doing these deals?

MR. CARGAS: No.

MR. MARTIN: Why not?

MR. CARGAS: One other feature of these deals is that the sponsor has a call at year five to buy out the tax equity investor, and the tax equity investor has a withdrawal right at year six essentially to force a buyout if the sponsor call has not been exercised. One wonders in the wind arena how a transaction like that, which has a likely termination five or six years out, is useful to a sponsor who would like to see the transaction last for at least the 10-year PTC period. There may also be some concerns about whether the withdrawal right is a put that is likely to be exercised so that the tax equity is a fixed-term investment.

MR. MARTIN: Tom Festle, are these deals attractive to you as a wind company CFO?

MR. FESTLE: I agree with Jack that we are unlikely to consider them for a wind project because we do not want to have to finance the project twice. We would rather cover the whole PTC period right out of the box. Solar may be another story.

MR. GOARMON: Bernardo Goarmon, are these deals attractive to EDP?

MR. GOARMON: Not in wind.

MR. MARTIN: Yale Henderson, is JPMorgan doing them?

MR. HENDERSON: No.

MR. MARTIN: Kenji Ogawa?

MR. OGAWA: No.

Cash Strips

MR. MARTIN: Yale Henderson, coming back to you, JPMorgan tried for years to develop the secondary market for tax equity paper. Has such a market developed and, if so, how would you characterize it?

MR. HENDERSON: Yes. We have done a number of secondary market transactions selling the cash portion of our tax equity position to interested cash investors where the flip date has been delayed beyond the 10-year horizon. I think it is a growing market. We are aware of other tax equity investors who are looking into doing similar transactions. We will continue to actively manage our portfolio using this tool in the future.

MR. MARTIN: Why shed the cash portion of your tax equity position?

MR. HENDERSON: The impetus was the deals had not or were not expected to flip on schedule. We wanted to manage the tail risk and not have a large residual sitting there at year 10, so we decided to be a little more proactive in managing our portfolio. Those were very early partnership flip deals that we did during the period 2003 through 2006. I think we have gotten a lot smarter about how to predict wind output. Those tails on more recent deals will be a lot shorter. The impetus to do additional deals on new facilities will not be as great.

MR. MARTIN: I have two more questions. How receptive is the tax equity market to merchant wind deals? Can they be done on a standalone basis or only as part of a larger portfolio?

MR. HENDERSON: Merchant can get done on a standalone basis.

MR. MARTIN: Only with a 12-year hedge?

MR. HENDERSON: Without any hedge.

MR. MARTIN: Without any hedge at all. In what parts of the country?

MR. HENDERSON: Where you have a good merchant market.

MR. MARTIN: ERCOT and PJM. Anywhere else? New England?

MR. HENDERSON: Not in New England.

MR. CARGAS: I don’t know what you mean by merchant. If you are talking about hedge transactions, we have been doing a lot of these deals, and they have a true merchant piece in that some percentage of the output is not, in fact, hedged. The hedge deals that we are doing at Bank of America use Merrill Lynch Commodities as the hedge counterparty. We are doing transactions like that. Pure merchant transactions? No. Are we doing transactions that have some percentage of the output unhedged and are, therefore, merchant? Yes.

MR. MARTIN: What percentage: 25%? Higher?

MR. CARGAS: It depends on what you are measuring. If you are measuring cash flow or PTCs, then yes: 20%, 25%, 30%.

MR. MARTIN: Yale Henderson, I understood you to say you can do a pure merchant deal without a hedge. Did I misunderstand?

MR. HENDERSON: No. We have done those in rare instances, but they have been done.

MR. MARTIN: Is that because another part of JPMorgan is taking the price risk, as Jack Cargas described for Bank of America?

MR. HENDERSON: No. There are deals structured so that the tax equity investor can reach its return, if necessary, largely on PTCs and depreciation and, therefore, the exposure to merchant price risk is small and over collateralized. With proper structuring, you can do a hedge deal with the right sponsor and the right project.

MR. FESTLE: Maybe we are that type of sponsor. When we make an investment decision on a site, we are willing to stand behind the wind assessment.

MR. GOARMON: We do not like merchant, it is not in our DNA, but when we do it, we fold the project into a portfolio so that it is financed as part of a larger portfolio that limits the exposure to the tax equity investors.

MR. MARTIN: Last question. With the benefit of hindsight, how successful was the Treasury cash grant program?

MR. CARGAS: It was very successful. It was not perfect and there was some difficulty in administration, but the use of that technique during a period when there was really low tax capacity on offer in the market was very important for advancing renewable energy in this country. We would not be as far along as we are today were it not for that program. It provided liquidity when the market would otherwise have lost momentum.


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